This section is intended to introduce various aspects of the art, which may be associated with the present technological advancement. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present technological advancement. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
In the oil and gas industry, seismic prospecting techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon deposits. A seismic prospecting operation consists of three separate stages: data acquisition, data processing, and data interpretation.
In the data acquisition stage, a seismic source is used to generate a physical impulse known as a “seismic signal” that propagates into the earth and is at least partially reflected by subsurface seismic reflectors (i.e., interfaces between underground formations having different acoustic impedances). The reflected signals (known as “seismic reflections”) are detected and recorded by an array of seismic receivers located at or near the surface of the Earth, in an overlying body of water, or at known depths in boreholes. The seismic energy recorded by each seismic receiver is known as a “seismic data trace.”
During the data processing stage, the raw seismic data traces recorded in the data acquisition stage are refined and enhanced using a variety of procedures that depend on the nature of the geologic structure being investigated and on the characteristics of the raw data traces themselves. In general, the purpose of the data processing stage is to produce an image of the subsurface geologic structure from the recorded seismic data for use during the data interpretation stage. The image is developed using theoretical and empirical models of the manner in which the seismic signals are transmitted into the Earth, attenuated by the subsurface strata, and reflected from the geologic structures. The quality of the final product of the data processing stage is heavily dependent on the accuracy of the procedures used to process the data.
The purpose of the data interpretation stage is to determine information about the subsurface geology of the earth from the processed seismic data. For example, data interpretation may be used to determine the general geologic structure of a subsurface region, or to locate potential hydrocarbon reservoirs, or to guide the development of an already discovered reservoir. Obviously, the data interpretation stage cannot be successful unless the processed seismic data provide an accurate representation of the subsurface geology.
In exploration geophysics, seismic velocity model building followed by imaging is a routinely used method to depict subsurface geological structures around target oil and gas reservoirs. When understanding of regional geological structures is needed, multiple 2D seismic surveys are often conducted in a target area, and then processed line by line, resulting in a seismic image and velocity model for each individual line. If multiple 2D lines are intersecting each other, seismic image or velocity at intersecting locations often does not match each other because of: 1) random noise and measurement error in data causes inconsistent velocity updates from each line even at the same spatial location; 2) reflection tomography, commonly used in industry to improve an existing velocity model, is based on nonlinear inversion where model changes at each iterative update can vary depending upon several factors (e.g., data selection, initial model and smoothing constraint); and 3) 2D models from 2D reflection tomography often cannot represent real 3D earth, especially when geological structures are highly dipping. This is the so called out-of-plane effect; waves do not necessarily travel within a 2D plane between source and receiver because seismic wave propagation is governed by seismic properties of the earth (i.e., seismic velocity), usually varying spatially in 3D.
In-consistent seismic images at the same spatial location of intersecting points from different 2D lines makes it difficult to interpret for a correct regional geological structure from those seismic images. In order to make seismic image or velocity at a same spatial location consistent for multiple 2D lines, industry often takes two distinct approaches; 1) after generating a seismic image based on a certain velocity model and data from each line, shift seismic traces to be consistent at intersecting points by manual or automatic process (Walters, 1992), or 2) before generating a seismic image, develop a velocity model for each line which makes corresponding seismic images be consistent at intersecting points (so that there is no need to arbitrarily shift or alter seismic traces near intersecting points, to match them each other).
In order to develop 2D velocity models which makes seismic images be consistent for intersecting lines, industry sometimes applies 3D tomography using 3D source and receiver geometries, obtaining a 3D velocity model, from which a 2D model is extracted. It can be reliable for a variety of acquisition types including crooked 2D line, but is not efficient for 2D lines intersecting with large azimuth, i.e., around 90 degrees, and is sometimes computationally impractical for high resolution updates, if an acquisition line is too long.
Another alternative approach is to perform 2D tomography for each line, and manually adjust velocity at intersecting locations. This 2D line-by-line approach is computationally efficient and can handle a very long acquisition lines. However, it requires extra work to adjust velocity to make seismic images tied at intersecting points, which can be difficult to reconcile especially when many lines are intersecting each other.